The exemplary embodiments described herein relate to measuring the viscosity of drilling fluids.
Wellbore fluids often include a plurality of particles that impart specific properties (e.g., viscosity, mud weight (or density), and the like) and capabilities (e.g., wellbore strengthening) to the wellbore fluid. It should be understood that the terms “particle” and “particulate,” as used in this disclosure, includes all known shapes of materials, including substantially spherical materials, fibrous materials, polygonal materials (such as cubic materials), and combinations thereof.
In drilling fluids, for example, weighting agents and viscosifiers can be used to produce drilling fluids with the desired viscosity, which affects the pumpability and equivalent circulating density (“ECD”) of the drilling fluid. During drilling operations, for example, the ECD is often carefully monitored and controlled relative to the fracture gradient of the subterranean formation. Typically, the ECD during drilling is close to the fracture gradient without exceeding it. When the ECD exceeds the fracture gradient, a fracture may form in the subterranean formation and drilling fluid may be lost into the subterranean formation (often referred to as lost circulation).
During drilling, the drill bit breaks up the formation into smaller pieces referred to as drill cuttings. These drill cuttings affect the viscosity of the drilling fluid. Accordingly, the viscosity of the drilling fluid is measured often during drilling operations. Such measurements are typically not automated and complex, which decreases the accuracy of the measurements.